Transient CO 2 leakage and injection in wellbore‐reservoir systems for geologic carbon sequestration

At its most basic level, the injection of CO 2 into deep reservoirs for geologic carbon sequestration (GCS) involves a system comprising the wellbore and the target reservoir, the wellbore being the only conduit available to emplace the CO 2 . Wellbores in general have also been identified as the most likely conduit for CO 2 and brine leakage from GCS sites, especially those in sedimentary basins with historical hydrocarbon production. We have developed a coupled wellbore and reservoir model for simulating the dynamics of CO 2 injection and leakage through wellbores, and we have applied the model to situations relevant to geologic CO 2 storage involving upward flow (e.g. leakage) and downward flow (injection). The new simulator integrates a wellbore‐reservoir system by assigning the wellbore and reservoir to two different sub‐domains in which flow is controlled by appropriate laws of physics. In the reservoir, we model flow using a standard multiphase Darcy flow approach. In the wellbores, we use the drift‐flux model and related conservation equations for describing transient two‐phase non‐isothermal wellbore flow of CO 2 ‐water mixtures. Applications to leakage test problems reveal transient flows that develop into quasi‐steady states within a day if the reservoir can maintain constant conditions at the wellbore. Otherwise, the leakage dynamics could be much more complicated than the simple quasi‐steady‐state flow, especially when one of the phases flowing in from the reservoir is near its residual saturation. A test problem of injection into a depleted (low‐pressure) gas reservoir shows transient behavior out to several hundred days with sub‐critical conditions in the well disappearing after 240 days. © 2011 Society of Chemical Industry and John Wiley & Sons, Ltd